Stress as in subterranean formations are usually determined in order to design formation fracturing operations, but typically these stresses are determined empirically by applying pressure to the formation from a wellbore until a fracture initiates. Typically, formation stresses will not be important variables in design of wellbore tubulars because the tubular strength is dictated by the necessity of the tubular to support a significant length of itself. This is not the case when the wellbore is to be used as a heat injection well in a thermal recovery project. The casing will only have to support itself until it is cemented into place. This is done when the casing is relatively cool. When the heat injection well is placed in service, the casing will be heated to a temperature that is preferably between about 1400.degree. F. and 2000.degree. F. The thickness of the casing must be sufficiently thick so that, at these conditions, the casing will not buckle due to formation stress. This thickness is much greater than what is required to support a significant length of the casing.
Even if the initial formation stress is determined prior to beginning heating operation of a heat injection well, the initial stress may not be indicative of the stress over the entire cycle of the heating operation. The cost of the tubulars, and the casing in particular, are a major portion of the initial cost of the heat injection well, and therefore it would be desirable to know what the formation stresses on the casing are during the operation of the heat injection well. For example, the operating temperature of the well may be limited initially if the formation stress increases initially due to heating of the rocks, and then the operating temperatures might be increased later in the process if formation stresses decrease.
An obvious alternative to determine the stress a formation is placing on a casing would be to attach a strain gauge directly to the casing. This would be a simple and direct solution, but such a strain gauge would be subject to errors including a large zero-drift as the tubular is subject to creep during the life of the casing, and leakage of the signal over a long electrical leads to the surface. These errors would render the strain gauge application less than acceptable for long-term monitoring of formation stress.
Various methods are also available to measure the fluid pressure within a formation. These methods do not determine the total pressure on the casing, but only the fluid pressure.
Because there is presently no method available to determine actual formation stress during operation of a wellbore, it would be desirable to provide such a method. It is therefore an object of the present invention to provide a method to determine the stress within a formation during the operation of a wellbore.